Hydrocarbons, such as oil and gas, may be recovered from various types of subsurface geological formations. The formations typically consist of a porous layer, such as limestone and sands, overlaid by a nonporous layer. Hydrocarbons cannot rise through the nonporous layer, and thus, the porous layer forms a reservoir in which hydrocarbons are able to collect. A well is drilled through the earth until the hydrocarbon bearing formation is reached. Hydrocarbons then are able to flow from the porous formation into the well.
In what is perhaps the most basic form of rotary drilling methods, a drill bit is attached to a series of pipe sections referred to as a drill string. The drill string is suspended from a derrick and rotated by a motor in the derrick. A drilling fluid or “mud” is pumped down the drill string, through the bit, and into the well bore. This fluid serves to lubricate the bit and carry cuttings from the drilling process back to the surface. As the drilling progresses downward, the drill string is extended by adding more pipe sections.
When the drill bit has reached the desired depth, larger diameter pipes, or casings, are placed in the well and cemented in place to prevent the sides of the borehole from caving in. Cement is introduced through a work string. As it flows out the bottom of the work string, fluids already in the well, so-called “returns,” are displaced up the annulus between the casing and the borehole and are collected at the surface.
Once the casing is cemented in place, it is perforated at the level of the oil bearing formation to create openings through which oil can enter the cased well. Production tubing, valves, and other equipment are installed in the well so that the hydrocarbons may flow in a controlled manner from the formation, into the cased well bore, and through the production tubing up to the surface for storage or transport.
This simplified drilling and completion process, however, is rarely possible in the real world. Hydrocarbon bearing formations may be quite deep or otherwise difficult to access. Thus, many wells today are drilled in stages. An initial section is drilled, cased, and cemented. Drilling then proceeds with a somewhat smaller well bore which is lined with somewhat smaller casings or “liners.” The liner is suspended from the original or “host” casing by an anchor or “hanger.” A seal also is typically established between the liner and the casing and, like the original casing, the liner is cemented in the well. That process then may be repeated to further extend the well and install additional liners. In essence, then, a modern oil well typically includes a number of tubes wholly or partially within other tubes.
Moreover, hydrocarbons are not always able to flow easily from a formation to a well. Some subsurface formations, such as sandstone, are very porous. Hydrocarbons are able to flow easily from the formation into a well. Other formations, however, such as shale rock, limestone, and coal beds, are only minimally porous. The formation may contain large quantities of hydrocarbons, but production through a conventional well may not be commercially practical because hydrocarbons flow though the formation and collect in the well at very low rates. The industry, therefore, relies on various techniques for improving the well and increasing production from formations which are relatively nonporous.
One technique involves drilling a well in a more or less horizontal direction, so that the borehole extends along a formation instead of passing through it. More of the formation is exposed to the borehole, and the average distance hydrocarbons must flow to reach the well is decreased. Another technique involves creating fractures in a formation which will allow hydrocarbons to flow more easily. Indeed, the combination of horizontal drilling and fracturing, or “frac'ing” or “fracking” as it is known in the industry, is presently the only commercially viable way of producing natural gas from the vast majority of North American gas reserves.
Fracturing typically involves installing a production liner in the portion of the well bore which passes through the hydrocarbon bearing formation. In shallow wells, the production liner may actually be the casing suspended from the well surface. In either event, the production liner is provided, by various methods discussed below, with openings at predetermined locations along its length. Fluid, most commonly water, then is pumped into the well and forced into the formation at high pressure and flow rates, causing the formation to fracture and creating flow paths to the well. Proppants, such as grains of sand, ceramic or other particulates, usually are added to the frac fluid and are carried into the fractures. The proppant serves to prevent fractures from closing when pumping is stopped.
A formation usually is fractured at various locations, and rarely, if ever, is fractured all at once. Especially in a typical horizontal well, the formation usually is fractured at a number of different points along the bore in a series of operations or stages. For example, an initial stage may fracture the formation near the bottom of a well. The frac job then would be completed by conducting additional fracturing stages in succession up the well.
Some operators prefer to perform a frac job on an “open hole,” that is without cementing the production liner in the well bore. The production liner is provided with a series of packers and is run into an open well bore. The packers then are installed to provide seals between the production liner and the sides of the well bore. The packers are spaced along the production liner at appropriate distances to isolate the various frac zones from each other. The zones then may be fractured in a predetermined sequence. The packers in theory prevent fluid introduced through the liner in a particular zone from flowing up or down the well bore to fracture the formation in areas outside the intended zone.
Certain problems arise, however, when an open hole is fractured. The distance between packers may be substantial, and the formation is exposed to fluid pressure along that entire distance. Thus, there is less control over the location at which fracturing of a formation will occur. It will occur at the weakest point in the frac zone, i.e., the portion of the well bore between adjacent packers. Greater control may be obtained by increasing the number of packers and diminishing their separation, but that increases the time required to complete the frac job. Moreover, even if packers are tightly spaced, given the extreme pressures required to fracture some formations and the rough and sometimes frangible surface of a well bore, it may be difficult to achieve an effective seal with a packer. Thus, fluid may flow across a packer and fracture a formation in areas outside the intended zone.
In part for such reasons, many operators prefer to cement the production liner in the well bore before the formation is fractured. Cement is circulated into the annulus between the production liner and well bore and is allowed to harden before the frac job is commenced. Thus, frac fluid first penetrates the cement in the immediate vicinity of the inner openings before entering and fracturing the formation. The cement above and below the liner openings serves to isolate other parts of the formation from fluid pressure and flow. Thus, it is possible to control more precisely the location at which a formation is fractured when the production liner is first cemented in the well bore. Cementing the production liner also tends to more reliably isolate a producing formation than does installing packers. Packers seat against a relatively small portion of the well bore, and even if an effective seal is established initially, packers may deteriorate as time passes.
There are various methods by which a production liner is provided with the openings through which frac fluids enter a formation. In a “plug and perf” frac job, the production liner is made up from standard lengths of casing. The liner does not have any openings through its sidewalls. It is installed in the well bore, either in an open bore using packers or by cementing the liner, and holes then are punched in the liner walls. The perforations typically are created by so-called perforation guns which discharge shaped charges through the liner and, if present, adjacent cement.
The production liner typically is perforated first in a zone near the bottom of the well. Fluids then are pumped into the well to frac the formation in the vicinity of the perforations. After the initial zone is fracked, a plug is installed in the liner at a point above the fractured zone to isolate the lower portion of the liner. The liner then is perforated above the plug in a second zone, and the second zone is fracked. That process is repeated until all zones in the well are fractured.
The plug and perf method is widely practiced, but it has a number of drawbacks. Chief among them is that it can be extremely time consuming. The perf guns and plugs must be run into the well and operated individually, often times at great distance and with some difficulty. After the frac job is complete, it also may be necessary to drill out or otherwise remove the plugs to allow production of hydrocarbons through the liner. Thus, many operators prefer to frac a formation using a series of frac valves.
Such frac valves typically include a cylindrical housing that may be threaded into and forms a part of a production liner. The housing defines a central conduit through which frac fluids and other well fluids may flow. Ports are provided in the housing that may be opened by actuating a sliding sleeve. Once opened, fluids are able to flow through the ports and fracture a formation in the vicinity of the valve.
The sliding sleeves in such valves traditionally have been actuated either by creating hydraulic pressure behind the sleeve or by dropping a ball on a ball seat which is connected to the sleeve. Typical multi-stage fracking systems will incorporate both types of valves. Halliburton's RapidSuite sleeve system and Schlumberger's Falcon series sleeves, for example, utilize a hydraulically actuated “initiator” valve and a series of ball-drop valves. Hydraulically actuated initiator valves also are disclosed in U.S. Pat. No. 8,267,178 to M. Sommers et al.
More particularly, the production liner in those systems is provided with a hydraulically actuated sliding sleeve valve which, when the liner is run into the well, will be located near the bottom of the well bore in the first fracture zone. The production liner also includes a series of ball drop valves which will be positioned in the various other fracture zones extending uphole from the first zone.
A frac job will be initiated by increasing fluid pressure in the production liner. The increasing pressure will actuate the sleeve in the bottom, hydraulic valve, opening the ports and allowing fluid to flow into the first fracture zone. Once the first zone is fractured, a ball is dropped into the well and allowed to settle on the ball seat of the ball-drop valve immediately uphole of the first zone. The seated ball isolates the lower portion of the production liner and prevents the flow of additional frac fluid into the first zone. Continued pumping will shift the seat downward, along with the sliding sleeve, opening the ports and allowing fluid to flow into the second fracture zone. The process then is repeated with each ball-drop valve up hole from the second zone until all zones in the formation are fractured.
Such systems have been used successfully in any number of well completions. The series of valves avoids the time consuming process of running and setting perf guns and plugs. Instead, a series of balls are dropped into the well to successively open the valves and isolate downhole zones. It may still be necessary, however, to drill out the liner to remove the balls and seats prior to production. Unlike plug and perf jobs, there also is a practical limit to the number of stages or zones that can be fractured.
That is, the seat on each valve must be big enough to allow passage of the balls required to actuate every valve below it. Conversely, the ball used to actuate a particular valve must be smaller than the balls used to actuate every valve above it. Given the size constraints of even the largest production liners, only so many different ball and seat sizes may be accommodated. Halliburton's RapidStage ball-drop valves, for example, only allow up to twenty intervals to be completed. While that capability is not insignificant, operators may prefer to perform an even greater number of stages using a single liner installation.
Sliding sleeves which are controlled using radio frequency identification (RFID) technology have been proposed for use in frac valves, and various RFID controlled sliding sleeve valves have been used in other well operations. For example, U.S. Pub. Appl. 2007/0,285,275 to D. Purkis et al. discloses a circulation sub having a sliding sleeve valve which is used to control circulation through a drill string. As drilling progresses and drilling mud is circulated through a well, pressure imbalances can occur along the drill string that make it more difficult to sweep cuttings up to the surface. By incorporating various valves in the drill string, such issues may be addressed by selectively diverting fluid out of the drill string through the valves.
The circulation subs disclosed in Purkis '275 generally comprise a cylindrical housing that may be threaded into a drill string. The housing has a central conduit through which drilling fluids are circulated. Ports are provided in the housing to allow fluid to be diverted from the central conduit into the well bore. A sleeve is mounted on the interior of the housing in a recess in the central conduit. The sleeve is actuated by pumping hydraulic fluid above a piston integrally formed in the sleeve. As fluid is pumped above the piston, the sleeve will slide away from and uncover the ports.
The hydraulic pump is controlled by a programmable electronic controller. The controller is connected to a RFID antenna which is adapted to pick up signals from encoded RFID transmitters passed through the drill string. When an operator wishes to open the sleeve in a particular valve, an “open valve” signal is encoded into an RFID transmitter. The signal is unique for that particular valve. When the RFID transmitter is pumped through the drill string and is detected by the corresponding valve, the pump is actuated to open the valve. Other valves in the drill string may be opened by circulating additional RFID transmitters through the drill string.
U.S. Pat. No. 7,252,152 to M. LoGiudice et al. and U.S. Pat. No. 7,503,398 to M. LoGiudice et al. disclose RFID-controlled sliding sleeve valves which are similar in many respects to the valves disclosed in Purkis '275. The LoGiudice valves are disclosed for use as casing circulation diverter tool, as part of a stage cementing apparatus, or for other unspecified downhole fluid flow regulating apparatus. Like the Purkis '275 valves, the valves disclosed in LoGiudice '152 and LoGiudice '398 have a sliding sleeve that is mounted on the interior of the tool housing in a recess in a central conduit. The valves have a programmable controller connected to an RFID antenna which can detect an encoded signal from a RFID tag passed through the conduit. The sleeve is actuated, however, by a linear actuator instead of the hydraulic pump provided in the Purkis '275 valves.
Such RFID controlled sliding sleeve valves may have certain advantages in the context of the specific well operations for which they are intended. They do not rely on differing ball sizes to actuate the sleeves, and so a greater number of valves may be incorporated into a particular conduit. They are not well suited, however, for incorporation into a production liner and use in fracking operations. Frac fluids typically include proppants, such as grains of sand, ceramic or other particulates, which can be quite abrasive and can interfere with the operation of sliding sleeve valves. Moreover, if the production liner will be cemented in place prior to fracturing the formation, cement passing through the valve conduit when the casing is cemented may hang up in the valve and interfere with subsequent operation of the sleeve.
The statements in this section are intended to provide background information related to the invention disclosed and claimed herein. Such information may or may not constitute prior art. It will be appreciated from the foregoing, however, that there remains a need for new and improved sliding sleeve frac valves and for new and improved methods for fracking formations using sliding sleeve frac valves. Such disadvantages and others inherent in the prior art are addressed by various aspects and embodiments of the subject invention.